It is common practice to deliver oilfield chemicals to a subterranean hydrocarbon reservoir to bring about a variety of functions at various stages of hydrocarbon production. Examples of oil field chemicals are scale inhibitors, hydrate inhibitors, corrosion inhibitors, biocides, and wax and asphaltene control substances.
Oilfield fluids are complex mixtures of aliphatic hydrocarbons, aromatics, hetero-atomic molecules, anionic and cationic salts, acids, sands, silts, clays and a vast array of other components. The nature of these fluids, combined with the severe conditions of heat, pressure, and turbulence to which they are often subjected during retrieval, are contributory factors to paraffin deposition (including the precipitation of wax crystals), emulsification (both water-in-oil and oil-in-water), gas hydrate formation, corrosion and asphaltene precipitation in oil and/or gas production wells and surface equipment. This, in turn, decreases permeability of the subterranean formation, reduces well productivity and shortens the lifetime of production equipment. In order to remove such unwanted deposits and precipitates from wells and equipment, it is necessary to stop the production which is both time-consuming and costly.
Further examples of oil field chemicals are thickeners and gel breakers used in hydraulic fracturing. Hydraulic fracturing is a well-established technique for stimulating production from a hydrocarbon reservoir. In a conventional fracturing procedure, a thickened aqueous fracturing fluid is pumped into the reservoir formation through a wellbore and opens a fracture in the formation. Thickened fluid is then also used to carry a particulate proppant into the fracture. Once the fracture has been made and packed with proppant, pumping is stopped. The formation closes onto the proppant pack and oil or gas can flow through the proppant pack to the wellbore. At least some of the aqueous fracturing fluid in the wellbore will be driven back to the surface by fluid produced from the reservoir. The fracturing fluid is subsequently pumped out and hydrocarbon production is resumed. As the fracturing fluid encounters the porous reservoir formation, a filter cake of solids from the fracturing fluid builds up on the surface of the rock constituting the formation. A thickener, which increases the viscosity of the fracturing fluid, can be a polysaccharide. Guar gum, often cross-linked with borate or a zirconium compound, is frequently used. Another category of thickeners which are used are viscoelastic surfactants. An oilfield chemical can be delivered to a reservoir during fracturing. If the fracturing fluid contains a viscosifying thickener, it is normal to supply a so-called breaker (which is usually an oxidizing agent, an acid or an enzyme) into the fracture to degrade the thickener and so reduce the viscosity of the fluid in the fracture after it has served its purpose. This facilitates the flow back to the surface and the flow of produced fluid through the proppant pack towards the wellbore.
A further example of an oil field chemical is chemical tracers used for monitoring of hydrocarbon reservoirs.
Optimal oil production from the reservoir depends upon reliable knowledge of the reservoir characteristics. Traditional methods for reservoir monitoring include seismic log interpretation, well pressure testing, production fluid analysis, production history matching and interwell tracer techniques. Due to the complexity of the reservoir, all information available is valuable in order to give the operator the best possible knowledge about the dynamics in the reservoir. One common secondary oil recovery process is water injection in dedicated injection wells. The water may travel in different layers and sweep (flow across) different areas in the reservoir. Monitoring of the production of this water in different zones in the well is important to design a production program that improves the sweep efficiency and thereby increase oil recovery. Mixing of injection water and formation water originally present in the reservoir may cause supersaturated solutions leading to precipitation of particles (scale) in either the reservoir near-well zone or in the production tubing. By knowing which zone or zones contribute to water production, action can be taken to reduce the effect of scaling and thereby maintain productivity.
The use of tracers to obtain information about a hydrocarbon reservoir and/or about what is taking place therein has been practiced for several decades and has been described in numerous documents. Tracers have primarily been used to monitor fluid paths and velocities. More than one tracer substance can be used concurrently. For instance, U.S. Pat. No. 5,892,147 discloses a procedure in which different tracers are placed at respective locations along the length of a well penetrating a reservoir. The tracers are placed at these locations during completion of the well before production begins. The tracer at each location is either attached to a section of pipe before it is placed at that location or is delivered into the location while perforating casing at that location. When production begins, monitoring the proportions of the individual tracers in the oil or gas produced by the well permits calculation of the proportions of oil or gas being produced from different zones of the reservoir.
Tracers have been used in connection with hydraulic fracturing, mainly to provide information on the location and orientation of the fracture. Tracers can also be used for estimating residual oil saturation. Tracers have been used in single well tests and in interwell tests. In single well tests, a tracer is injected into the formation from a well and then produced out of the same well mixed with fluids from the well. The delay in time needed to return to the ground between a tracer that does not react with the formation (a conservative tracer) and one that does (a partitioning tracer) will give an indication of residual oil saturation, a piece of information that is difficult to acquire by other means. In interwell tests, the tracer is injected at one well along with a carrier fluid, such as water in a waterflood, and detected at a producing well after some period of time, which can range from days to years.
Radioactive and chemical tracers have been used extensively in the oil industry and hydrology testing for decades. Non-radioactive chemical tracers offer distinct advantages over the use of radioactive tracers. For example, there are more unique chemical tracers than radioactive tracers and no downhole logging tools are required.
Oilfield chemicals are normally formulated with adjuvant or carrier chemicals before being introduced into a reservoir. When the formulated material is a liquid, the liquid can be pumped down a wellbore to the reservoir. When the formulated material is a solid, it can be pre-placed onto equipment, such as the well bore, before the equipment is placed in the well. Particles of the oil field chemicals may be absorbed into the pores of porous carrier particles or encapsulated in a structure in which the oilfield chemical is enclosed within a shell of carrier material around the oil field chemical, and the particles are suspended in a fluid and pumped downhole into the reservoir.
Despite the very wide usage of oil field chemicals, many of the current methods of introducing and using these chemicals have disadvantages.
One issue is the difficulty in handling oilfield chemicals that are in different physical states. For example, when different tracers are placed at their respective locations along the length of a well penetrating a reservoir, a stable solid form of a tracer formulation is normally used. Compared to solid tracers, tracers in liquid and gas form are often difficult to formulate and shape into stable solid objects. This can limit the types of tracers that can be used.
Another issue is that some oil field chemicals are reactive, making them difficult to formulate and deliver into the reservoir.
A further issue is that unwanted inhomogeneous compositions can result from formulating some oil field chemicals. This is found when attempting to formulate different tracers with polymers to form objects for application to hydrocarbon reservoirs. Tracers can differ from each other with respect to a variety of properties, such as density, particle size, and in various surface related properties. These differences can be very significant. For example, it is known that the density of oil tracers can vary from 1 to 3 g/cm3 and these differences can result in various problems. The differences between the densities of the tracers can result in compositions comprising a tracer and polymer having significant non-homogeneous structure and morphology. High density tracers tend to settle during the formulation process used to form the tracers into objects. Such non-homogeneous objects tend to show undesired release behavior in a subterranean reservoir environment. Although the use of an extra dispersing/stabilizing additive in the formulation of the objects can partially alleviate this problem, other associated problems, such as poor mechanical strength in a reservoir environment, remain. As a result, sometimes even apparently similar tracers in one family cannot be formulated in the same way.
One of the most important issues is the release of oil field chemicals from formulated articles to the targeted fluid or reservoir areas. While it is often a requirement for oil field chemicals to be released in a sustained manner, e.g. slowly so that treatment can be effective over long periods of time (e.g., years), the release of the chemicals in current commercial practice is often too fast (less than 6 months) and not up to the needs of the industry. As a result, some oil field chemicals have to be repeatedly introduced into wells to ensure that the requisite level of the well treatment agent is continuously present in the well. The release of oil field chemicals, such as tracers, is often not controlled in current practice, causing significant variations over time for both a single tracer and as well as between different tracers. Such issues often result in ineffective treatments or loss of monitoring of the reservoir, and result in lost production revenue due to down time and the costs of the additional materials that are used retreat the wells.